Kathleen Lally - Investor Relations Ralph Izzo - Chairman, President and Chief Executive Officer Dan Cregg - Executive Vice President and Chief Financial Officer

Julien Smith - Bank of America/Merrill Lynch Praful Mehta - Citigroup Christopher Turnure - JPMorgan Travis Miller - MorningStar, Inc. Paul Patterson - Glenrock Associates Michael Lapides - Goldman Sachs Jonathan Arnold - Deutsche Bank

Ladies and gentlemen, thank you for standing by. My name is Shelby and I will be your event operator today. I would like to welcome everyone to today’s conference, Public Service Enterprise Group Third Quarter 2017 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded, Tuesday, October 31, 2017 and will be available for telephone replay beginning at 1 o’clock PM Eastern Time today until 11:30 PM Eastern Time November 7, 2017. It will also be available as an audio webcast on PSEG’s corporate website at www.pseg.com. I would now like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Shelby. Good morning. Thank you everyone for participating in PSEG’s call this morning. As you are aware, we released our third quarter 2017 earnings statements earlier today. The release and attachments as mentioned are posted on our website at www.pseg.com under the Investors section. We also posted a series of slides that detail operating results by company for the quarter. Our 10-Q for the period ended September 30, 2017 is expected to be filed today. As you know, the earnings release and other matters that we will discuss in today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties. And although we may elect to update forward-looking statements from time-to-time, we specifically disclaim any obligation to do so, unless required to do so. Our release also contains certain non-GAAP operating information. Please refer to today’s 8-K or other filings for a discussion of factors that may cause results to differ from management’s projections, forecasts and expectations and for a reconciliation of our non-GAAP operating information to GAAP results. I would now like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. And joining Ralph on the call is Dan Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions.

Thank you, Kathleen and thank you everyone for joining us today. PSEG reported results for the third quarter having executed well on major operational and policy initiatives. Despite the impact of abnormally cool weather on sales and earnings, we remain within our non-GAAP operating earnings guidance for the full year of $2.80 to $3 per share. Earlier this morning, we reported net income for the quarter of $0.78 per share, non-GAAP operating earnings for the third quarter of 2017 were $0.82 per share compared with net income of $0.64 per share and non-GAAP operating earnings for the third quarter of 2016 of $0.88 per share. For the 9-month period, non-GAAP operating earnings were $2.36 per share, which is the same as non-GAAP operating earnings for 2016’s first 9 months. Slides 5 and 6 contain the detail on the results of the quarter and the 9 months. At PSE&G, earnings per share declined $0.01 per share from the prior year comparable quarter. The results for the third quarter were affected by cooler than normal weather which reduced demand for electricity from air conditioning. The weather comparisons for last year are stark. For instance, the measure of average temperature and humidity was 27% below the year ago quarter and the number of hours at temperature equal to or greater than 90 degrees was 69% below the year ago quarter. PSE&G’s expanded investment in transmission and distribution continue to benefit customers and had a favorable impact on PSE&G’s earnings. PSE&G’s rate base is forecasted to grow 12% in 2017 reaching $17 billion. The forecast is based on the continuation of PSE&G’s investment program to upgrade its transmission and distribution infrastructure. The upgrades will entail full year capital expenditures of approximately $3.1 billion. This figure is slightly less than our original budget of $3.4 billion and it’s the result of some projects being moved to 2018 and improved efficiency related to the cost of other projects. Based on further development of our various investment programs, we are increasingly comfortable with PSE&G’s ability to achieve growth in the rate base at the upper end of our forecast of 7% to 9% per year for the 5-year period ending in 2021. Our updated forecast assumes reasonable reception by the New Jersey Board of Public Utilities to PSE&G’s proposal to invest $540 million per year over 5 years to accelerate the pace of replacement of aging cast iron and unprotected steel mains and their associated services. Approval would support expansion and extension of the work currently being performed under the gas system modernization program. This filing was made in July and we expect to be a few to take action during the first half of 2018. We also intend to request the multiyear expansion of Energy Strong in the near-term. PSE&G is in the final stages of work previously approved as part of Energy Strong to strengthen and harden infrastructure damage during Hurricane Irene and Superstorm Sandy. The extension will address the remaining electric substations that need to be raised or projected. In addition, some other much needed work that enhances the resiliency of our system and reduces the risk of outages. That request similar to GSMP 2 will be consistent with the BPU’s draft regulation supporting multiyear capital investments under its infrastructure investment program. If the draft regulations are approved as we expect before year end, utilities will be able to proceed with 5-year investment programs that will allow more certainty in staffing and planning of work. Now, I want to bring you up-to-date on PSE&G’s distribution base rate proceeding. As you maybe aware following discussions with BPU staff and rate counsel and as approved by the BPU at its October 20 meeting, the deadline for filing our distribution rate case was deferred from November 1 to no later than December 1 of this year. The change in the filing date is simply an administrative procedural matter. We will now be providing the BPU with 3 months of actual data and 9 months of forecast data for the same test year that will end on June 30, 2018. A review of PSE&G’s distribution rates which is expected to result in a modest change in revenue is primarily driven by the need to recover investments made outside of cost mechanism since the last rate case, to recover storm costs and to allow PSE&G to reset assumptions for growth and sales in O&M. As part of the filing, PSE&G will also be seeking approval to decouple electric and gas distribution revenue from sales volumes and demand which would support larger scale energy efficiency investments. We believe that with the right regulatory policies, the states utilities can provide the energy infrastructure that meets customer requirements and creates a stronger and more efficient New Jersey. Now, let me turn to PSEG Power. Our PSEG Power, non-GAAP operating earnings declined by 9% to $0.31 per share from the prior year comparable quarter. A lower average price on energy hedges was partially offset by Power’s continued efforts to lower its costs and Power’s favorable gas supply position. PSEG Power also made progress on construction activities related to its three new natural gas combined cycle generation stations. The new stations will add 1,800 megawatts of efficient capacity over 2018 and 2019 and represent a reconfiguration of Power’s merchant fleet that will improve its efficiency and competitive position in the market. The design of the wholesale energy market and where the current policies provide adequate recognition of the cost for generation to be available is getting the attention needs. The Department of Energy issued a Notice of Proposed Rulemaking at the end of September regarding the need to properly value baseload generation with robust onsite fuel characteristics. We hope their interest in this important issue will jumpstart efforts by the Federal Energy Regulatory Commission to implement improvements in the market. It is encouraging to see that FERC has acted quickly. To meet the DOE’s 60-day requirement for response, FERC requested comments on the DOE NOPR to be filed by October 23 with reply comments due on November 7. A response by the FERC to the DOE NOPR is anticipated by December 11 of this year. PSEG filed comments in support of DOE’s initiative to immediately address the erosion occurring in the resiliency of our electric grid due to the risk of premature retirements of baseload generation and the subsequent trend towards greatly reduced fuel diversity. We believe that the DOE NOPR is necessary to address the challenges facing distressed yet valuable resources such as nuclear in the absence of a market solution that recognizes the attributes of fuel diversity and resilience. We recommend that measures adopted in response to the DOE NOPR should be viewed as an interim until effective mechanisms can be developed that recognized these attributes in the market. The current market design distorts efficient outcomes due to the disharmony between price signals, public policies and generation dispatch implementing the DOE measure as an interim step which stabilized the earnings for qualified units until a comprehensive market-based solution can be integrated into RTO and ISO market designs. It is worth mentioning that a significant amount of generation that competes in the PJM market already falls under cost of service regulation. We believe the DOE NOPR also provides the necessary impetus to push for further action by FERC to address longstanding price formation reforms that would avoid some of the continued distortions of competitive market results that disadvantage baseload resources. The PJM energy price formation proposal should be evaluated as part of the comprehensive solution to the challenges facing baseload units. As part of our response, we have requested that FERC promptly finalized the fast start pricing reforms and direct PJM through the Commission’s Federal Power Act Section 206 authority to submit its energy price formation proposal especially as it pertains to inflexible units. Getting energy prices right is critical to ensuring that the correct signals are sent to incent efficient investment as well as market exit. PSEG Power is making every effort to preserve its nuclear asset base, working in concert with the industry to identify means of improving operating efficiency without sacrificing safety. PSEG Power is on track in 2017 to reduce the all-in cost per megawatt hour of its nuclear operations by 10% from the average cost experienced during the prior 3 years, but energy prices influenced by the availability of natural gas have declined by a greater degree during this timeframe. State action also remains critical to prevent the loss of these units. We believe state action can be done the way that both maintains the integrity of the wholesale market and serves as a bridge until a regional federal solution is in place. A strong legal foundation has been established for state actions to preserve generating assets critical to meeting the state’s emission-related goals and to maintain the benefits to the state’s economy that comes with the safe, reliable operation of nuclear power. Successful execution of PSEG’s key policy and regulatory initiatives would assure the company’s ability to provide customers with the service, reliability and resiliency that they have come to expect. That is also affordable. Successful execution of our key policy and regulatory initiatives would also provide our shareholders with greater assurance of PSEG’s ability to meet our objectives for returns and growth. With that, I will turn the call over to Dan to discuss our financials in greater detail.

Thank you, Ralph and thanks everyone for joining us today. As Ralph said, PSEG reported net income for the third quarter of 2017 of $0.78 per share versus net income of $0.64 per share in last year’s third quarter. Non-GAAP operating earnings for the third quarter of 2017 were $0.82 per share versus non-GAAP operating earnings of $0.88 per share in last year’s third quarter. A reconciliation of non-GAAP operating earnings to net income for the quarter and 9 months can be found on Slides 5 and 6. We have also provided you with a waterfall chart on Slide 11 that takes you through the net changes in quarter-over-quarter non-GAAP operating earnings by major business and a similar chart on Slide 13 provides you with the changes in non-GAAP operating earnings by major business on a year-to-date basis. I will now review each company in more detail. Starting with PSE&G, PSE&G reported net income of $0.49 per share for the third quarter of 2017 compared with $0.50 per share for the third quarter of 2016. Results for the quarter are shown on Slide 15. Net income growth in the third quarter associated with PSE&G’s expanded investment in transmission and electric and gas distribution facilities was offset by the impact on sales of weather conditions, which were substantially cooler than experienced in the year ago quarter and cooler than normal. Returns on PSE&G’s expanded investment in transmission added $0.04 per share to net income in the quarter. Incremental revenue associated with the recovery of PSE&G’s Energy Strong Investment Infrastructure program, which added $0.02 per share to net income was offset by a decline in weather normalized electric sales and in electric demand related revenues. Demand related revenues were impacted by the significantly lower peak temperature hours, which as Ralph mentioned, were 69% lower than the year ago quarter and 47% below normal. Net income comparisons were also hurt by weather conditions, which were approximately 27% cooler than conditions experienced during 2016 in the third quarter and 5% cooler than normal. Electric sales as a result of the cooler summer weather declined 8.3% in the quarter. The decline was led by an approximate 14% decline in sales to residential customers. On a trailing 12-month basis, weather normalized electric sales were flat year-over-year and gas sales on a similar basis increased 1.5% led by the commercial sector. The decline in electric residential sales reduced third quarter net income comparisons by $0.03 per share, an increase in depreciation expense of $0.01 per share associated with PSE&G’s expanded capital base was offset by a decline in O&M expense and absence of tax credits available in the year ago quarter and other items reduced net income comparisons in the third quarter by $0.02 per share. PSEG’s 5-year capital investment plan includes approximately $6 billion to upgrade and expand transmission-related facilities and investment. PSE&G filed an update of its formula rate for transmission at the Federal Energy Regulatory Commission in October 2017 and the update which reflects an increase in the level of PSE&G’s investment in transmission and a true-up of prior year results provides for a $212 million increase in annual transmission revenues effective January 1, 2018. PSE&G under Energy Strong and the cost mechanism therein adjust electric rates 2x per year in March and September and gas rates are adjusted each year in September. Under the cost mechanism for the gas system modernization program, PSE&G gas rates in January of each year to reflect the investment made during the prior year. The combined annual revenue increase for the full year in 2017 for these two programs is forecasted to be approximately $56 million. As Ralph mentioned, PSE&G as agreed to delay the filing of its distribution rate case by 1 month to no later than December 1, 2017. This filing as you recall was agreed to as part of the Energy Strong settlement and provides the opportunity for PSE&G to recover capital investments made outside of existing cost mechanisms, an update for other factors such as storm costs and changes in sales growth in O&M. The distribution base rate filing will be based on a test year ending June 2018 and a 10.3% return on equity and provide for a mid single-digit increase in revenues still leaving overall rates below the level coming out of the last distribution base rate case in 2010. The 1 month delay in the filing hasn’t changed any of the economics associated with the request as the test year is unchanged that allows one criminal month of actual results to be included in the filing. PSE&G invested approximately $2.1 billion for the 9 months ended September 30 in electric and gas distribution and transmission capital projects designed to provide more reliable safe and resilient service to its 2.2 million customers. For the year, PSE&G currently expects to invest $3.1 billion on upgrading its infrastructure. And this is slightly lower than the $3.4 billion we originally forecast for 2017. A delay in timing of some projects in greater cost-related efficiencies on others are the primary reasons for the decline in the forecasted spending for the full year. As Ralph mentioned, as a result of identifying incremental investments, we now expect PSE&G’s investment program for the 5 years ended 2021 will provide growth in rate base of 2016 year end amounts at the upper end of our 7% to 9% per year growth rate. This is driven by incremental investments in our GSMP 2 filing relative to what is reflecting in our base capital plan and planned expansion of our Energy Strong filing. These important initiatives built confidence in PSE&G’s ability to extend its growth beyond the end of this decade. For 2017, we are maintaining our forecast of PSE&G’s net income at $945 million to $985 million. Now, let’s to Power. PSED Power reported net income of $136 million or $0.27 per share. For the third quarter of 2017 compared with net income of $139 million or $0.27 per share for the year ago quarter. Non-GAAP operating earnings were $0.31 per share for the third quarter of 2017 compared to non-GAAP operating earnings for the third quarter of 2016 of $0.34 per share. Non-GAAP adjusted EBITDA for the third quarter of 2017 was $356 million versus non-GAAP operating EBITDA for 2016 of $387 million. Our non-GAAP adjusted EBITDA excludes the same items as our non-GAAP operating earnings measure as well as income tax expense, interest expense and depreciation and amortization. The earnings release and Slide 19 provide you with detailed analysis of the impact on Power’s non-GAAP operating earnings quarter-over-quarter and we have also provided you with more detail on generation for the quarter and the first 9 months of the year on Slide 20 and 21. Power’s net income in the third quarter was impacted by a decline in average energy hedge prices and the effect of cooler than normal weather on demand and output which offset a decline in operating and maintenance expense. During the quarter, non-GAAP operating earnings comparisons increased $0.01 per share as a result of higher capacity prices in New England and PJM. This increase in capacity prices occurred on June 1, 2017 and will run through May 31, 2018. Lower average prices on energy hedges and a decline in market prices combined to reduce non-GAAP operating earnings comparisons by $0.05 per share, a 6% decline in output associated with the impact of cooler than normal weather on demand, reduced non-GAAP operating earnings comparisons by an additional $0.02 per share. Power’s focus on improving operational efficiencies help mitigate the impact of the decline in energy prices. The June 1, 2017 retirement of the Hudson and Mercer coal stations and a decline in nuclear plant related O&M, improved non-GAAP operating earnings by $0.02 per share and a decline in depreciation expense associated with the retirement of Hudson and Mercer combined with a decline in interest expense and taxes improved non-GAAP operating earnings comparisons by $0.01 per share. Now, let’s turn to Power’s operations. Output of Power’s generating stations declined 6% in the quarter and nuclear fleet’s output increased 20% in the third quarter to 8.2 terawatt hours as the fleet’s capacity factor improved to 96% from 80%. The quarter-over-quarter improvement was due to strong performance at Oak Creek, which operated at an average capacity factor of 98.4% in the absence of an extended refueling outage and repairs at the Salem station in the year ago quarter, which addressed the repair and replacement of baffle bolts at Salem 1 and repair of the transformer at Salem 2. The nuclear fleet’s performance for the third quarter brought the capacity factor for the 9 months ended September 30 to 95%. As mentioned cooler than normal weather limited energy pricing peak demand requirements and utilization of gas-fired combined cycle and peaking fleet, Power’s combined cycle fleet experienced a 29% decline in output to 3.7 terawatt hours while an increase in the price of gas improved the competitive position of the baseload coal fleet. As we indicated earlier this year, average hedge prices during the second, third and fourth quarters of the year were expected to decline by less than what we experienced in the first quarter and by less than the average decline of $5 per megawatt hours we anticipated for the full year. This reflects the absence of weather-related risk premium during the winter months that was experienced in prior years. Gas prices improved in the third quarter, but since Power prices didn’t move in conjunction with gas, spark spreads declined relative to year ago levels. Power’s realized spark spreads held up better than the market declining $1 per megawatt hour quarter-over-quarter given its beneficial gas supply position. And Power’s beneficial gas supply position also held gross margins in the quarter to a decline of $1.50 per megawatt hour to $40 per megawatt hour. Power continues to forecast output for 2017 of 49 to 50 terawatt hours. Approximately 86% of production for the remainder of the year of approximately 11 terawatt hours is hedged at an average price of $45 per megawatt hour. Power has hedged approximately 70% to 75% of 2018’s forecast output of 52 to 54 terawatt hours at an average price of $41 per megawatt hour. And for 2019, Power has hedged 30% to 35% forecasted output of 58 to 60 terawatt hours at an average price of $39 per megawatt hour. The average price for energy hedged in 2019 is $2 per megawatt hour lower than our prior forecast and the reduction reflects a decline in market prices. The forecast of output for 2018 and 2019 remains unchanged from prior estimates. Forecasted increase in output in both 2018 and ‘19 reflects the commercial startup in mid ‘18 of 1,300 megawatts of new gas-fired combined cycle capacity at the Keys Energy Center in Maryland and at Sewaren in New Jersey. And the forecast increase is also supported by the commercial startup in mid-2019 of the 485 megawatt gas-fired combined cycle facility in Bridgeport Harbor, Connecticut. Our forecast of Power’s full year 2017 non-GAAP operating earnings remains unchanged at $435 million to $510 million. The forecast represents non-GAAP adjusted EBITDA of $1.80 billion to $1.210 billion. Now, let me turn briefly to PSEG Enterprise and other, which reported net income of $0.02 per share for the third quarter 2017 compared with a net loss of $0.13 per share for the third quarter of 2016. Results for the third quarter of 2016 were impacted by the impairment of the REMA leases. Non-GAAP operating earnings for the third quarter of 2017 were $0.02 per share compared with non-GAAP operating earnings of $0.04 per share for the third quarter of 2016. The decrease in non-GAAP operating earnings quarter-over-quarter reflects the absence of certain tax items recognized in the third quarter of 2016, as well as higher interest expense at the parent. And the forecast for enterprise and other for the full year 2017 non-GAAP operating earnings remains unchanged at $35 million. PSEG also closed the quarter ended September of 2017 with $287 million of cash on its balance sheet and with debt at the end of the quarter representing approximately 49% of consolidated capital. PSEG Power had debt at the end of the quarter representing 31% of capital. And as Ralph mentioned, we are maintaining our guidance for 2017 non-GAAP operating earnings of $2.80 to $3 per share. And Shelby, we are now ready to take questions.

[Operator Instructions] Your first question comes from Julien Smith from Bank of America/Merrill Lynch.

Hi, good morning.

Hi, Julien. Welcome back to the fray.

Thank you so much. I appreciate it. So perhaps just to kick it off a little bit here on the New Jersey and some of the background with the politics here, I would be curious one, do you think there is potential for reform in New Jersey just given what’s already going on at the FERC level? And then secondly in that same vein of thinking, how do you think about the potential for our more comprehensive review of energy mix obviously there is some considerations with respect to solar in addition to the nuclear issue that you have addressed as well as just your ongoing utility spend in the extension and expansion of those programs. So to the extent to which that legislation might be a fixed for all, I would curious how that might be shaping up?

Sure, Julien. Yes, I do think that depending on what happens at the federal level, there remains the opportunity for New Jersey to recognize certain attributes that perhaps are not explicitly identified at the federal level. To the extent that the federal level does recognize the same attributes then you would not have redundant programs. So, an example of that might be you could have price formation improvements at the federal level just to make the market more efficient sort of along the lines of what PJM has talked about with inflexible units and that doesn’t do anything explicitly for fuel diversity or resiliency and therefore New Jersey could have an overlay on top of that. Similarly, fuel diversity versus carbon would be mutually exclusive, but if both jurisdictions recognized carbon, then you would not have two programs overlapping each other. Those are just types of examples I would think about in terms of state and federal programs being complementary versus redundant. To your second question, whenever you have a change in administration and as you implied, Governor Christie is term limited, now he is finishing his second term, has a desire on the part of the new incoming administration to establish themselves in various ways, it could be environmental, it could be the economy, it could be education and both candidates have talked about their desire to look at things a little bit differently when it comes to energy policy discussions about REGI and green energy targets and we absolutely as we have done for 110 years we absolutely will work with the incoming administration to understand their policy objectives and inform them as the implications both about positive and negatives of whatever we want to be done, because as we know things cost money to do, but if the benefits outweigh the costs, then we are eager to help them pursue it. So, yes, we will work closely with whoever the new governor is to help them formulate and execute their energy policy. Lastly, I think you are correct and if I could say implicit remarks that an ongoing investment in the infrastructure is something that is no matter who comes into office will probably be supportive of and I do think that’s correct, there is a widespread recognition on the part of regulators and policymakers that we have an aging infrastructure that’s not perfectly suited for the growing dependency that people have on electricity nowadays and the improvements we are making will certainly continue proposed, but I think will be well received.

Excellent. Thank you for that. Just a follow-up again congratulations on moving higher within your range here at the top end on the rate base side, can you talk about reconciling that against earnings and some of the key factors that might be relevant in the current rate case and/or through the current period just in an attempt to reconcile the rate base trajectory against kind of hitting the upper end of that earnings, perhaps items might include like an authorized equity ratio or other deferred items in the context that we should be paying attention to you once it’s filed?

Yes. Our last base rate case was in 2010 and we have done a very good job of controlling O&M expense, but circumstances have conspired against us by having complete actions of low growth over that time. So, even a very good job of controlling O&M expense loses out to no load growth. We have also as you know had some of the clauses anticipate this rate case. So, we had some un-recovered CapEx and we had some modest investment levels above depreciation that served to build the rate base to levels that were not commensurate with what was in the 2010 rate case. That’s a really longwinded way of saying we need some rate relief, but we have managed our overall portfolio well enough that we are describing this is a kind of middle single-digit type of rate increase, which will be far below the compounding of CPI over the last 7 years that one might otherwise have expected. So, I think it will be something that is easily explained. Now, the 7% to 9% figure in rate base is more a prospective conversation. And my last 3 minutes was really looking in rearview mirror, but now as I look out the windshield, basically we have as you know in our 7% number, programs that were wholly approved than the 7% to 9% number anticipated some fairly high degree of confidence in some program extensions. And I think what you are hearing in our voices today is that, that confidence has grown as we have been able to put our engineers to work and understand some of parts of the system both gas and electric that needs strengthening. So, as you think ahead to earnings and as you know we don’t forecast earnings beyond the current year, the three levers you have in the regulated utility are earnings grow with load, I think down we are seeing 0.4%, 0.5% is the forecast.

Within the last 12, that’s about right.

And then you are subtracting that O&M, we have been pretty good at controlling that and you add to that the clauses that we expect to get recovery of. So, its two additions and one subtraction and you will get pretty close to what the utility should look like in the coming 5 years.

Got it. So, let me just make sure what I am hearing you say is it shouldn’t be all that different notwithstanding any kind of uncertainties with respect to the case?

I think that’s correct within the limitation of as you know we don’t smooth for pension. So, some massive change in pension funding which we don’t expect we are 92% funded right now, but the equity ratio could be adjusted in the case to – we are probably going to ask [indiscernible] more, a bit more than we used to have in the past and so yes, the case could set a new base from which that upper end of the 7% to 9% can grow.

Excellent. Alright. I’ll leave it there. Thank you all very much. Good luck.

Thanks, Julien.

Your next question comes from Praful Mehta of Citigroup.

Thanks so much. Hi, guys.

Hi, Praful.

Hi, Praful.

So I got the point of this decks and the DOE being mutually exclusive just wanted to understand given, Ralph, your initial comments on the DOE initiative, how do you see it playing out like do you see it as dollar per megawatt and dollar per megawatt hour. Do you see – how do you see that actually playing out and do you see that how much in terms of benefit you expect for your facilities?

Yes, probably, so, of course, probably I wish I could answer that with definitiveness, but let m answer it with the way which we proposed that to be played out, which may or may not have any bearing with what actually happens. In our comments to FERC, we basically said first of all bringing PJM in under Section 206 to do what PJM says needs to be done is a no-brainer. So, the inflexible unit treatment, they fast start reforms, that is long overdue what needs to be done and that is the easy part. Others have estimated that could be anywhere from $2 to $4 per megawatt hour. Others have estimated that. Secondly, as this specifically pertains to the DOE recommendations put forth in a NOPR, we have pointed out that there is a substantial portion of PJM that is competitively positioned in the market, but yet receives cost of service rates from their state regulators. And on an interim basis that can be replicated at the federal level through a version of RMR type reliability, must run type contracts. So the units that are at risk of premature retirement and that would be an interim solution until one comes up with a market-based solution that values the diversity associated with these different field types. We have proposed one method that relates to tranching of the capacity markets, others have proposed methods that relate to scarcity, pricing and energy markets for different fuels, but that permanent solution will involve a longer discussion with affected stakeholders. So really, it’s three steps, it’s hey, there is plenty of evidence already that fast start and inflexible unit price formation needs to be fixed now and can happen now, interim solution for at risk of premature retirement using a cost of service methodology can be put in place very easily and then a longer term market-based solution. There are known solutions and options that people can pursue, but a more fulsome discussion would not be inappropriate in that regard.

Got it. That’s very helpful color, Ralph. And secondly, in terms of long-term views, I know you’ve talked about long-term the generation business probably not being as part of the consolidated business over the long-term. Now, given what’s happening with the IPP space and either company is going public or shrinking given the mergers. How do you see that playing out? Has that changed in anyway? Do you now see Power being more part of the business going forward or has that view on separation is still hold at this point?

No, the view still holds, but I think it’s pretty obvious to us to at least, but right now in the short-term with all of the conversations taking place at FERC, at DOE, at the state, with new entrants being formed in anticipating the Vistra Dynegy combination with all the entrants exiting in terms of public markets, anticipating the Calpine going private. I think it’s – this is a good time to just sort of wait and let something settle out of it, right. So, we are in a great shape. Power is a cash generator and earnings producer. And about 15 months, Power will be a healthy free cash flow generator. The utility has an insatiable appetite for that cash. So, we are not in any hurry during this period of tremendous change, all healthy, all very healthy given the dialogues taking place at FERC and given the dialogue taking place at the state to let it kind of play out while we enjoy the benefits of the two companies being together. That doesn’t change the fact that we continually assess our strategic flexibility going forward on whether these two businesses belong together or not. And I standby my prior belief that I think over the long-term they do diverge.

Got it. And just to be clear that time of change is what 2, 3-year period while all of this benefit is down, do you think it’s…

I did make that mistake about 3 or 4 years ago. I may not be this large, first off all, but I do learn from those mistakes, I am not going to give you that, nice try.

Alright. Thanks, guys.

Almost it’s like the gasoline started like choking me, so my voice broke a little bit.

Thank you, guys.

You’re welcome.

Your next question comes from Greg Gordon of Evercore ISI.

Hi, it’s [indiscernible] here. Good morning.

Good morning.

I just want to see if you could quantify the uplift in PJM price reform as it’s currently being contemplated?

So, Kevin what we quoted is what other sources have talked about if you just take Dan’s comments about 55 terawatt hours, every $1 is worth $55 million pre-tax. So, if it’s $2 to $4, but I just strung three if statements in there, so please be aware of that. You come up with the impact on us. Dan, did you want to add some color there?

No, I mean I think that’s right. I think there has been an awful lot of people that have put out some numbers on it. They have actually coalesced around that range pretty tightly. So, we will see as these different initiatives get done what it ends up looking like, but I think that seems to be a reasonable place to lot of the [indiscernible]. We think it’s pretty reasonable as well, Kevin.

Okay. So, now how would that impact your hedging? Would you like hedge less or stop hedging ‘19 if you start to see progress or how do you think about that?

So we have constantly disciplined ourselves to staying within a certain range in terms of how much we hedge, we have various parameters, gross margin at risk, standard VAR calculations. We do allow our ERNT folks, our trading organization to float high and low in that range depending upon what’s going on. To the extent that the whole market anticipates price formation you should start seeing that in the forward price curve and therefore our hedging approach would stay the same. We do challenge ourselves if we think the market is missing something to make darn sure that we can figure out why the market will be missing it before we would push one boundary or another, but in general, we will run a place to where we always have which is not assume we are smarter than the market and to just stay within those limits, but again, those limits are range and we do let our folks have some flexibility within that range.

Okay, great. Thanks a lot.

[Operator Instructions] The next question comes from Christopher Turnure of JPMorgan.

Good morning, guys. I wanted to get maybe a little bit more detail on the rate case last year and in particular, kind of the true-up in what’s included in that. I guess that would kind be a third quarter event after the test year ends on June 30, but I am just trying to get a sense as to how next year will shape up there and what the rate case will ultimately include in terms of timing coming out of the gate?

So, Christopher, we had originally planned to file November 1 per the agreement we made back in May of 2014 coming out of Energy Strong. There was widespread recognition that, that will be 2 in 10 and there was preference for 3 months of actuals and 9 months of forecast as opposed to 2 months of actuals and 10 months of forecast and that was the primary driver behind the 1 month delay, if you will. So, there is nothing mystical or profound going on there. So, the test year still ends in June of ‘18. As I mentioned before, we are expecting mid single-digit, we are requested to increase that will still keep rates below where they were in 2010 when we had our last base rate case. Remember, we have $250 million of GSMP stipulated rate base that was not covered by GSMP. We have about $100 million of Energy Strong above the $1 billion that was in the clause. We have storm recovery cost that’s I think $200 million something. That was deemed prudent, but hasn’t been returned to us yet. We have some new business that added to the CapEx. And candidly, we had some additional capital that was above depreciation levels that were accumulated over the course of the year. So, we would anticipate rates going into effect October, November of next year. And I don’t want to front-run the filing, we owe to the board staff. So, let them be the first ones to read the details, but Dan if you want add any thoughts.

Just one thing, Chris, it sounded like your question was implying there would be a rate case and then there would be a true up afterwards and the way that we describe the rate case is basically it is a truing up host of the things that Ralph just talked about. So we will come out of the rate case with the rates that are set within that case and historically we’ve seen a settlement in these cases and in the statement and that may well be where it ends up going, what we’ll see. We would look for rates next fall usually these are taken about a year and we would hope to anticipate that we can get rates may be in like the October range, but it’s a little different than our transmission formula rate which is file those rates going to effect for the following year and then there is a separate true up that happens the year after that. So just for clarity sake there is no true up after the rate case, rate case itself will true up our distribution rates and we would anticipate the new rates would be in effect say October of next year.

And just I think most of you know this, but our rate base is roughly half transmission, half distribution right now, so tiny but more distribution.

Okay, that was all very helpful context and I mean that’s kind of what I was driving at there towards the end-to-end just that the distribution rate case itself would have a 9-month forecasted test year, but that itself would never be trued up during the rate case process.

Yes, so the 9 months it will be a 12 year, 12 months test year and it will start with 3 months of actuals and 9 months of forecast and as we step through we’ll update those as we go forward.

Okay. So you would have some update on or something during the process?

Yes, yes.

Okay, got it. And then just on the request for decoupling can you help put that into context for me just kind of understanding your motivation for that and maybe how you think it may or may not be perceived by interveners?

Yes, Chris, we’ve had a series of energy efficiency filings approved over the past 7 or so years. I think they’ve totaled out about $400 million most $69 million past summer. And we have basically worked around this issue of fixed costs recovery with the stakeholders in these processes and it kept us from doing something in a much grander scale and we’ve simply decided that with the prospect of a new administration coming in and ongoing indication that there are market imperfections that keep customers from investing in energy efficiency despite the compelling economics of that that we would like to do this in a much more significant way, but we are not going to do it and suffer fixed cost losses at the options recovery of fixed costs. So given the traffic redesign involved with decoupling we thought well, since we are going in for rate case, now is a good time to raise the issue and that’s the motivation. The motivation really is not so much of this rate case, but the rate case is an opportunity to pave the way for significant energy efficiency proposals early next year.

Okay, great. Thanks, Ralph.

Your next question comes from Travis Miller of MorningStar, Inc.

Good morning. Thank you.

Hi, Travis.

I was wondering if we could boil down all of these power market issues and the two buckets, the price formation bucket and the fuel diversity bucket. How do you think about the next 2 to 3 years perhaps even more of capital investment based on what happens in either of those two buckets? So, what happens to the capital investment depending on the outcome [indiscernible] capital investment based on an outcome in fuel diversity?

Well, I can tell you what it means for us Travis is we are not deploying additional capital into the power generation business, we have 1,800 megawatts of 6,000 to 6,500 heat rate power plants coming online and we are quite happy with that. At the risk of speaking for others, which is always going to be wrong that PJM in particular many other markets are in oversupply situation and there has been reasonable demonstration of capital discipline in the most recent auctions that have taken place. So, I think that the supply demand imbalance that exists is a separate issue that will continue to impart that capital discipline and the price formation issue is just the recognition that if you want the market to be efficient, then price should determine who runs and who doesn’t and you can’t keep having uplift payments and sidebar out of market payments guiding the dispatch of the system, which is what PJM has going on right now. I mean, price is not the sole determinant of how the systems dispatch, then that’s not a market, so that needs to be fixed, so two separate issues I guess.

Okay, then got a reason that you don’t think there would be much capital investment in general across certainly the PJM region however this turns out?

I think you can, without question, read into it, but that’s our point of view. Again, I don’t want to speak for others, but I know what our capital plans are, is to finish these three projects and generate some healthy free cash flow for the utility.

Sure, sure. Okay, all my other questions are asked and answered. Thank you.

Your next question comes from Paul Patterson of Glenrock Associates.

I am sorry. Can you hear me?

Sure, Paul. There we can.

Sorry about that. So, just to follow-up on Travis’ question, what we often see with these market reforms is that others seem to deploy capital and I am just wondering when you see this $2 to $4 price increase with price formation we are potentially seeing that. How long-term do you think that would be or is the proposal, it’s hard for me to really completely get my arms around it? Is it such that you would still see location marginal pricing being set by inflexible units even with new entry showing up in the gas-fired area if you follow me. I mean, how should we think about sort of the sustainability of something like price formation given what we have seen quite frankly with the capacity markets and other “market reforms” to change the price that’s evolving?

So, Paul, I mean that’s fair, I think that one has to realize that there is cyclicality in these markets that have different periodicity associated with them, right, the cyclicality in fuel prices, the cyclicality in boom/bust cycles associated with oversupply and under supply, the cyclicality in oversupply and undersupplies determined by power plants being built and is determined by pipelines being built. So to simply say that price formation will drive prices up $3 picking the midpoint in the range that Dan and I have talked about which we don’t attest to, but simply quote from others and then automatically concluding that, that’s going to lead to people running the numbers and assuming that, that number stays there for the plants, it could be a little bit risky right. I mean, what does it mean for the timing of pipelines that may change the basis differential of gas in Western PJM versus Eastern PJM? What does it mean for future carbon constraints that may or may not be part of a subsequent administration in Washington? I think all of us want to go – some people on this call may want to go see their children in their Halloween parades, otherwise I would list a thousand other factors that should go into people’s thought process before making those kind of investment decisions.

Okay.

Just a matter, a market that is working better by virtue of some of the changes that need to be made is going to get you to a better answer.

Okay. And then with respect to the DOE proposal, I know this is kind of a sort of moon shot question I guess maybe, but how much assets should we think about is being potentially if it were to be enacted for you guys I mean how should we think about what the potential impact might be there? I mean, how many units – just how do we sort of quantify that, if that were to – I mean, I know it’s kind of a hard question maybe to answer, but I mean, how would you suggest we think about it?

I think Paul the way I will break it down is based upon how they have the DOE described the eligibility. So – and one of the main ones is having 90 days of fuel onsite. And if you think about what that means, that means our nuclear facilities certainly and it means our small interest in Keystone and Conemaugh.

So, all those units would theoretically be able to get rate of return rate base sort of what you are getting at the utility kind of thing?

We will see where the – ultimately where the NOPR goes with it, but certainly from an eligibility standpoint, those are the units that would come to mind.

Okay. And I guess we don’t have – do we have like a – what the asset, what the day base number would be kind of if you me associated with that, you thought what I am saying I mean…

Yes, I mean but there is a little bit of data related to some of the nuclear facilities in the Q, but it’s not on an asset-by-asset basis from a book value perspective.

Okay, well, I will follow-up afterwards. I mean I was just wondering, I was just curious if you had some sort of idea there, but I don’t want to hold it up. Thank you so much. Have a great one.

Okay.

[Operator Instructions] Your next question comes from Michael Lapides of Goldman Sachs.

Hi, hey guys, easy question your 2017 CapEx guidance, the reduction of 300 million, can you give a little more detail about what’s moving and does that get put back into a future years CapEx and if so how far out in the future?

Yes, Michael so it’s a little bit of a split, I think we had reference, there were a couple of things that were going on related to the total sum is frankly just doing some work more efficiently and I think there’s a the majority of that it is on energy strong you heard about talk a little bit earlier about $1 billion going through the clause and about 100 million that will await the rate case and you remember it's about a $1.2 billion program. So frankly, some of that work was done more efficiently and I think that’s a great outcome and then it’s great for customers and we’re pleased to be able to do it that way and we had a little bit of the same on transmission not a whole lot. And then the balance really is timing and the timing is not anything that’s going to move dollars out 3, 4, 5 years it just moving ‘17 out into ’18. So in the aggregate if you think it may be about half-and-half, half being just efficiencies that we brought to the process and about half being some capital that move into next year.

So when you think about efficiencies, if I did half-and-half reducing CapEx Over the cycle by about 150 million and pushing out 150 in the next year kind of ballpark?

Yes, if you think about that the 31 versus 34 that we talked about that’s about right, yes.

Got it. Okay.

That trend towards the upper end of the rate base growth through 2021 includes all of that thinking.

Got it. Okay. And then one other just thinking about transmission rate base growth and transmission capital needs and kind of how you’re thinking about whether there’s any lumpiness in some of what PJM is trying to plan around, given what happened with the [indiscernible] wheel. How are you thinking about just whether there are any lumpier or larger scale projects coming down the pike with transmission or is it all going to be just lots and lots and lots of kind of small and midsize ones?

Yes, it’s more the latter than the former, I think if you had gone back 3 or 4 years you would have found more bigger lumpier projects a fair bit of what we are spending now is around 29 – 69 KB upgrade of 26 KB systems and that actually moves capital from the distribution area into transmission as it goes up in voltage. And those are smaller now a lot of them are still sizable projects, but smaller than for instance a Susquehanna Roseland type of project that we talked about in the past. So there are more smaller projects, projects as opposed to fewer larger projects that we seen in the past that will us forward and in fact as we think about our 2018 revenue number that we talked about even within our prepared remarks some of what you see their it’s a is a step up from what we have seen in some prior years even if you look back to last year there’s a pretty sizable step up in the amount. Some of that is incremental capital year-over-year and both the return on that capital and the depreciation the return of that capital will contribute to some of that increase, but you may recall last year part of the number that we had from a revenue increase was inclusive of a true up and that true up was related to bonus depreciation, so a couple years back, the bonus depreciation extension took place ironically goes December 31, it was roughly close to that it was certainly after we had filed our October formula rate filing. So the impact of bonus depreciation in 2015, getting it approved moved into 2016 after we had set our rates in a true up in 2017 included the reduction in rate base for those excess deferred taxes for bonus depreciation. So on a year-over-year basis you’ll see a jump in a lot of that had to do with the fact that 2017 had a true up reducing revenues for transmission related to that late enactment of bonus depreciation back in 2015.

Got it guys. Thank you much appreciated. Maybe one last one O&M at the utility has been very strong meaning you produced O&M this year. How much of that is just one off stuff related to maybe storms in 2016 and how much of that is kind of active O&M management?

It is the latter. It’s active O&M management and we’ve kept O&M to a very manageable rate over frankly the last number of years and we look to continue to do so going forward.

Got it. Thanks Dan and much appreciate it.

Thanks, Michael.

Your next question comes from Jonathan Arnold of Deutsche Bank.

Hi, good morning, guys.

Good morning, Jonathan.

Hi, Jonathan.

I have just one on the hedging data that you mentioned that you would had a $2 down in the average price to 39 after 2019 and hedged amount ticked up by 5%. Can you just remind us does that include an estimate of the pricing on the open position or is that just the average price on the hedge piece?

It’s the latter, Jonathan.

Okay. So then I guess, following from that and between over the last four quarters it’s ticked down from 43 to 39 and the hedging is going from 15 to 30. How do we can reconcile that math?

Well, I think if you take a look at what the ‘19 – 2019 forwards it look like over that period, you’ve been in a $29, $30 rate and what you’re doing is you’re pulling down from a BGS price in those out years which is exclusive of the capacity components, but inclusive of the other. So it’s not an unusual trend that we start in the out year of our 3 year cycle with BGS and then we layer on flat hedges as well as some other low deals in those slack like just tend to come in at lower prices and part because the curve has come.

Right.

But also because their energy only hedges.

Okay. Sort of those two things going on that and then but also the curve is sort of the trade-off in the quarter and then recovered a couple of dollars since is a fair to say these were sort of down in the heart of the third quarter or can you give us any sense there?

Yes, during the quarter since our last update.

Okay. And then one other thing just on enterprises than the your guidance for ‘17 is 35 million number is that still the right ballpark going forward?

Yes, yes, that’s right.

Okay. I think that’s it. Thank you.

Excellent. Thanks Jon. So I’ll go next, I’m sorry if we one more question otherwise I never got over our allotted hours time, but I don’t want to cut anybody off with the significant questions. So we’ll allow one more question.

Okay. So your final question comes from [indiscernible].

Hi, how are you guys doing? [indiscernible] can I just ask through Ralph, can you just talk a little bit about the legislation if when we should kind of expected or what should we expect in the last 2 months starting tomorrow I guess November starts Buxton? And then I just had a one more question for Cregg was that could you remind us how much of the transmission increase went into effect on January 1 of the year. You said you’re going to requests something like 212 million, right January 1, 2018. Could you remind us what an amount was January 1, 2017?

So we are just in a series of conversations with people right now, we are just making sure they understand what are nuclear plans meaning to New Jersey. And yes it is true that if New Jersey were to build a safety net, so as to guarantee or sure the continued operation those plans it would require legislation, but anything more than that would be premature to discuss right. So there is just a lot of conversations that we’re having with folks to say. If those plan were near here’s what happened.

And then 2017, Dan?

Yes, 2017 was $121 million and that was down over the last couple of years, which is 146 and 182. So it’s moved around a fair bit a lot of that is the bonus depreciation not I’m going to talked about earlier.

So from $121 million we are now going to like $212 million right, am I correct?

That’s right.

Thank you so much.

So just to summarize what hopefully you heard from me and Dan this morning, our power plant construction is on budget and on schedule, three power plants that we hope to have online in June of next year and the subsequent June. We have a very healthy dialogue that we are active participants in going on under way on wholesale power market design and reform taking place at FERC, at DOE and at the state level. For the utility, we are now pointing toward the upper end of rate base growth at 7% to 9% range we are now thinking we will be able to hit that upper end of the range of between now and 2021. We have a very busy, but a constructive regulatory agenda coming up at PSE&G. We have GSMP in play. We have a rate case. We will have Energy Strong 2 in the near-term and longer term some energy efficiency. And we are happy to go over all of that and then some with you at EEI next week. I know we have a full set of meetings setup and if you are not on the meeting schedule, I am sure you can corner one of us in the hallway, they wouldn’t let me say it at the beginning of the script, but I wish everybody a Happy Halloween now and have a great holiday and a safe day. Thank you. We will see you all next week.

Ladies and gentlemen, that does conclude your conference call for today. You may disconnect and thank you for participating.